Successfully explored and delineated the Montney at West Bigstone with a drilling program that consisted of twelve (7.8 net) horizontal wells and brought on production twelve (7.8 net) horizontal Montney wells through significantly expanded infrastructure;

Increased proved developed producing, total proved and total proved plus probable reserves by one percent, 17 percent and 27 percent, respectively, from a successful drilling program in 2018;

Increased field condensate reserves, included in natural gas liquids ('NGL'), related to the Company's Montney shale gas reserves by 12 percent, 42 percent and 56 percent for proved developed producing, total proved and total proved plus probable reserves, respectively;

Field condensate to gas ratio for proved developed producing shale gas reserve extensions through drilling additions in 2018 was 99 barrels per million cubic feet of natural gas ('bbls/mmcf'), significantly higher than 53 bbls/mmcf for proved developed producing reserves in 2017;

Increased annual field condensate production by 29 percent, NGL's by 13 percent, and natural gas by 12 percent for an overall annual production increase of 16 percent to 9,774 boe/d in 2018 from 8,401 boe/d in 2017;

Increased the net present value (discounted at ten percent) of proved developed producing reserves by 16 percent through an increased weighting in Montney field condensate and a reduction in Montney operating costs;

Increased the net present value (discounted at ten percent) of total proved and total proved plus probable reserves by 18 percent and 26 percent respectively through a significant increase in undeveloped locations as a result of successful delineation drilling; and

At December 31, 2018, had undeveloped land of 62,310 net acres with an associated value of $32.1 million(1).

(1) As determined independently by Seaton-Jordan and Associates Ltd. in accordance with NI 51-101(1)(e).

RESERVES SUMMARY

GLJ Petroleum Consultants Ltd. ('GLJ'), the Company's independent petroleum engineering firm, has evaluated Delphi's crude oil, natural gas and natural gas liquids reserves as at December 31, 2018 and prepared a reserves report (the 'GLJ Report') in accordance with National Instrument 51-101 'Standards of Disclosure for Oil and Gas Activities' and the 'Canadian Oil and Gas Evaluation Handbook'. GLJ's price forecast dated January 1, 2019 was used in the evaluation. Company gross reserves in the total proved and total proved plus probable categories increased 17 percent and 27 percent respectively, compared to 2017. While Company gross reserves in the proved developed producing category grew by one percent, the field condensate component of natural gas liquids associated with the Montney grew by 12 percent, contributing to a growth in value for the category.

The following is a summary of reserves information detailed in the GLJ Report at December 31, 2018:

(1) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1). (2) Tables may not add due to rounding.

Net Present Value of Future Net Revenue

The net present value of future net revenues, discounted at ten percent, for proved developed producing reserves increased by 16 percent as a result of richer, more valuable boe's replacing production as well as the commissioning of the Company's Amine facility at Bigstone. This project, although only in operation for approximately eight months of 2018, was a key component in reducing operating costs in the Montney from $8.72/boe in 2017 to $7.65/boe in 2018. The net present value of future net revenues, discounted at ten percent, for total proved and total proved plus probable reserves increased by 18 percent and 26 percent respectively, compared to 2017. The estimated future net revenues associated with Delphi's reserves at December 31, 2018, based on the GLJ January 1, 2019 price forecast, are summarized in the following table.

(1) Future net revenues are estimated using forecast prices, costs arising from the anticipated development and production of reserves, associated royalties, operating costs, development costs, and abandonment and reclamation costs. The estimated values disclosed do not necessarily represent fair market value. (2) Unit values are calculated using net reserves defined as Delphi's working interest share after deduction of royalty obligations plus Delphi's royalty interests. (3) Tables may not add due to rounding.

Future Development Costs

Future development costs ('FDC') have increased by $83.2 million and $199.1 million for the total proved and total proved plus probable categories respectively, primarily as a result of new undeveloped locations being booked offsetting the successful delineation wells drilled in 2018.

The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.

($ millions) 2019 2020 2021 2022 2023 Rem Total

Total Proved 56 55 71 52 0 0 234

Total Proved Plus Probable 56 94 76 129 118 1 474

Forecast Prices

The following is a summary of GLJ's January 1, 2019 price forecast used in the evaluation.

Natural Gas Oil

AECO/NIT NYMEX Edmonton NYMEX Pentanes Plus Exchange

Spot Henry Hub Light WTI Edmonton Inflation Rate

Year $CDN/MMBtu $US/MMBtu $CDN/bbl $US/bbl $CDN/bbl % $US/$CDN

2019 1.85 3.00 63.33 56.25 67.67 0.0 0.750

2020 2.29 3.15 75.32 63.00 79.22 2.0 0.770

2021 2.67 3.35 79.75 67.00 83.54 2.0 0.790

2022 2.90 3.50 81.48 70.00 85.49 2.0 0.810

2023 3.14 3.63 83.54 72.50 87.80 2.0 0.820

2024 3.23 3.70 86.06 75.00 90.30 2.0 0.825

2025 3.34 3.77 89.09 77.50 93.33 2.0 0.825

2026 3.41 3.85 92.62 80.41 96.86 2.0 0.825

2027 3.48 3.93 94.57 82.02 98.81 2.0 0.825

2028 3.54 4.00 96.56 83.66 100.80 2.0 0.825

2029+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 2.0 0.825

Reserves(1) Reconciliation

The following reconciliation of Delphi's reserves compares changes in the Company's gross reserves at December 31, 2017 to the reserves at December 31, 2018, each evaluated in accordance with National Instrument 51-101 definitions. Negative technical revisions and economic factors to shale gas and associated natural gas liquids product types were primarily related to shale gas and the associated plant extracted natural gas liquids. Technical revisions and economic factors related to field condensate (included in the 'associated natural gas liquids' product type) were positive 7 mboe for total proved and negative 408 mboe for total proved plus probable.

Shale Gas Conventional Natural Gas

Shale Associated Natural Gas Natural Associated Natural Gas Total Oil

Gas Liquids Gas Liquids Equivalent

Proved (mmcf) (mbbls) (mmcf) (mbbls) (mboe)

December 31, 2017 93,933 9,574 8,370 230 26,854

Extensions and Improved Recovery 32,118 4,500 - - 9,853

Technical Revisions (8,033 ) (571 ) 848 59 (1,710 )

Discoveries - - - - -

Acquisitions - - - - -

Dispositions - - - - -

Economic Factors - - (129 ) (3 ) (24 )

Production (11,479 ) (1,389 ) (1,269 ) (53 ) (3,567 )

December 31, 2018 106,539 12,113 7,820 232 31,405

Shale Gas Conventional Natural Gas

Shale Associated Natural Gas Natural Associated Natural Gas Total Oil

Gas Liquids Gas Liquids Equivalent

Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)

December 31, 2017 76,377 7,536 6,784 236 21,633

Extensions and Improved Recovery 43,037 5,250 - - 12,423

Technical Revisions (14,376 ) (1,250 ) (156 ) 6 (3,666 )

Discoveries - - - - -

Acquisitions - - - - -

Dispositions - - - - -

Economic Factors (22 ) - (40 ) 1 (9 )

Production - - - - -

December 31, 2018 105,016 11,537 6,588 243 30,380

Shale Gas Conventional Natural Gas

Associated Associated

Shale Natural Gas Natural Natural Gas Total Oil

Gas Liquids Gas Liquids Equivalent

Proved Plus Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)

December 31, 2017 170,309 17,110 15,154 466 48,486

Extensions and Improved Recovery 75,155 9,750 - - 22,276

Technical Revisions (22,409 ) (1,821 ) 692 65 (5,376 )

Discoveries - - - - -

Acquisitions - - - - -

Dispositions - - - - -

Economic Factors (22 ) - (169 ) (2 ) (33 )

Production (11,479 ) (1,389 ) (1,269 ) (53 ) (3,567 )

December 31, 2018 211,554 23,650 14,408 475 61,786

(1) Gross reserves represent the operated and non-operated working interest share of reserves before deduction of royalties and does not include any royalty interests of the Company. (2) Tables may not add due to rounding. Finding and Development Costs

In 2018, Delphi brought twelve gross (7.8 net) wells on production. Capital to drill, complete, equip and tie-in these wells totaled $83.6 million which includes $15.0 million of capital spent on these wells in 2017 and excludes $22.4 million of capital spent in 2018 on major infrastructure and wells not brought on production in 2018. Included in these well costs is capital for major gathering and infrastructure costs in order to bring the delineation wells (particularly at West Bigstone) on stream. Company gross proved developed producing reserve additions (classified as extensions and improved recovery) for these wells was 4.5 mmboe resulting in a finding and development cost of $18.60 per boe. Finding and development costs for proved and proved plus probable reserves for 2018 and the last three years are presented below.

Delphi will release its Annual Information Form on or before April 1, 2019, which will include all required National Instrument 51-101 reserves disclosure.

Net Asset Value

The estimated net asset value of the Company at December 31, 2018 has been calculated using before tax, net present value of reserves discounted at ten percent as follows:

($ millions) Proved Plus Probable

Discounted (10%) net present value of reserves $386,163

Undeveloped land $32,074

Mark-to-market value of hedging contracts $26,626

Total assets value $444,863

Total debt plus working capital deficiency ($181,985 )

Net asset value $262,878

Common shares outstanding 185,547,351

Net asset value per share $1.42

YE2017 NAV per share $1.17

% change 21%

OPERATIONS UPDATE

The fourth quarter of 2018 was challenging for our industry with ongoing constraints on exports from the Western Canadian Sedimentary Basin coupled with a decline in international crude oil prices impacting the price received for our energy products. Differentials for all grades of crude oil and condensate were severely impacted by pipeline apportionment and lack of storage. With the curtailment of heavy oil production introduced by the Government of Alberta and easing of storage constraints, differentials to benchmark prices have significantly improved in recent months.

Production volumes for the twelve months ended December 31, 2018 averaged 9,774 boe/d, a 16 percent increase over the comparative period in 2017, while field condensate production volumes increased by 29 percent to 2,542 barrels per day ('bbls/day') over that same period.

Production volumes in the fourth quarter of 2018 averaged 9,444 boe/d, a two percent decrease over the comparative quarter in 2017. Field condensate comprised about 28 percent of production on a barrel of oil equivalent ('boe') basis while field condensate and natural gas liquids ('NGL') combined accounted for 42 percent of production. Production in the fourth quarter of 2018 was negatively impacted by approximately 1,270 boe/d due to a combination of ongoing completion operations impacting adjacent producing wells (685 boe/d); scheduled and unscheduled facility outages (410 boe/d); and, the permanent suspension of the Company's Tower Creek sour gas well in October (175 boe/d). The performance of impacted offset wells has continued to improve since being put back on production with the deficit of current performance to pre-fracing performance being reduced to about 80 boe/d. With the shift to multi-well pad operations the impact on base production from offset frac operations will be greatly reduced.

Given the very low condensate pricing in November and December, Delphi deferred the reactivation of some of its more condensate-rich production until January where differentials narrowed to more historical norms. January's realized condensate pricing, including its hedging gains was almost three times higher than December, and more consistent with realized pricing in the third quarter of 2018.

With delineation success at West Bigstone exhibiting robust production rates and higher condensate to gas ratios, Delphi has shifted its focus to development through multi-well pad operations in order to realize cost efficiencies while optimizing completion technique as well as diminish the impact of fracing operations on offset wells. The first three wells of a four-well pad were drilled in the fourth quarter of 2018 with drilling of the fourth well finishing in January 2019. Completion of these four wells have commenced and they are expected to be brought on production in the second quarter. These four wells are directly adjacent to the 16-10-60-24W5 ('16-10') and 15-10-60-24W5 ('15-10').

With the innovations on frac techniques utilized on 16-10- and 15-10, the average total IP30, IP90, and IP180 (for 16-10 only) of these two wells has exceeded the average west wells by 325 boe/d (31 percent), 334 boe/d (40 percent) and 355 boe/d (52 percent). The West Bigstone wells have averaged approximately 55 percent liquids over the first 180 days of production. Furthering these innovations through even tighter frac spacing and extreme limited entry frac technique coupled with the reduced capital that pad operation efficiencies provide gives line of sight to superior economics at Bigstone.

Through the first half of 2019, Delphi will focus on completing and bringing on production its four-well pad in West Bigstone. Facility upgrades and pipeline construction to route the West Bigstone production to Delphi's 7-11 facility in East Bigstone is expected to be completed in late March. Capital spending in 2019 will be in the context of cash flow. Drilling plans for the second half of 2019 will be dependent on both commodity prices and the results of the four-well pad currently being completed.

About Delphi Energy Corp.

Delphi Energy Corp. is an industry-leading producer of liquids-rich natural gas. The Company has achieved top decile results through the development of our high quality Montney property, uniquely positioned in the Deep Basin of Bigstone, in northwest Alberta. Delphi continues to outperform key industry players by improving operational efficiencies and growing our dominant Bigstone land position in this world-class play. Delphi is headquartered in Calgary, Alberta and trades on the Toronto Stock Exchange under the symbol DEE.

FOR FURTHER INFORMATION PLEASE CONTACT:

DELPHI ENERGY CORP.

2300 - 333 – 7th Avenue S.W.

Calgary, Alberta

T2P 2Z1

Telephone: (403) 265-6171 Facsimile: (403) 265-6207

Email: Website: www.delphienergy.ca

DAVID J. REID MARK D. BEHRMAN

President & CEO Chief Financial Officer

Forward-Looking Statements. This news release contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events or the Company's future performance and are based upon the Company's internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words 'expect', 'anticipate', 'continue', 'estimate', 'may', 'will', 'should', 'believe', "intends', 'forecast', 'plans', 'guidance', 'budget' and similar expressions. More particularly and without limitation, this release contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi's ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations.

Furthermore, statements relating to 'reserves' are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future.

The forward-looking statements and information contained in this release are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this release are based: the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management's expectations, production levels of Delphi being consistent with management's expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management's expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management's expectations, weather affecting Delphi's ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi's ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi's ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations.

Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations.

Financial outlook information contained in this release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this release should not be used for purposes other than for which it is disclosed.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company's operations or financial results are included in the Company's most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website ( www.sedar.com ).

Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this release are made as of the date of this release for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements contained in this release are expressly qualified in their entirety by this cautionary statement.

Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms to the Canadian Securities Administrators' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.

As per CSA Staff Notice 51-327 initial test results and initial production performance should be considered preliminary data and such data is not necessarily indicative of long-term performance or of ultimate recovery. 'IP' is an abbreviation for 'Initial Production' and represents average production rates over the indicated time period in producing days.

Non-GAAP Measures. The release contains the terms 'adjusted funds flow', 'adjusted funds flow per share', 'net debt', 'net debt to adjusted funds flow ratio', 'marketing income', 'operating netbacks', 'cash netbacks,' and 'netbacks' which are not recognized measures under GAAP. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices and costs of production. Management uses adjusted funds flow to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments, abandonment obligations and to repay debt. Adjusted funds flow is a non-GAAP measure and has been defined by the Company as cash flow from operating activities before decommissioning expenditures and changes in non-cash working capital from operating activities. The Company also presents adjusted funds flow per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi's determination of adjusted funds flow may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. The Company has defined net debt as the sum of bank debt, senior secured notes and the long term portion of unutilized take-or-pay contract plus/minus working capital deficit/surplus excluding the current portion of the fair value of financial instruments. Net debt is used by management to monitor remaining availability under its credit facilities. Marketing income is defined as the margin earned on the sale of purchased third party natural gas volumes and premiums received on the assignment of a portion of committed capacity on the Alliance pipeline system to a third party. Management considers marketing income important measures of the Company's ability to mitigate the cost of excess committed capacity. Operating netbacks have been defined as revenue plus marketing income less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less interest on bank debt and senior secured notes, general and administrative costs and cash costs related to the Company's restricted share units. Netbacks are generally discussed and presented on a per boe basis.